1. Field of the Invention
This invention relates generally to systems for drilling oilfield wellbores and more particularly to an integrated bottom hole assembly (BHA) for use in drilling wellbores. The BHA includes a drill bit and a variety of devices, sensor and interactive models. The BHA tests and calibrates sensors, and determines the operating condition of devices, formation parameters, wellbore condition, and the condition of the drilling fluid. The BHA utilizing such information and the models determines the desired operating parameters that will provide enhanced overall drilling performance and longer BHA operating life. The BHA takes actions to control the drilling operations based the computed parameters or upon command from the surface or a both and in accordance with a higher logic provided to the BHA, thereby improving the overall effectiveness of the drilling operations.
2. Description of the Related Art
Oilfield wellbores are formed by rotating a drill bit carried at an end of an assembly commonly referred to as the bottom hole assembly or "BHA." The BHA is conveyed into the wellbore by a drill pipe or coiled-tubing. The rotation of the drill bit is effected by rotating the drill pipe and/or by a mud motor depending upon the tubing used. For the purpose of this invention, BHA is used to mean the bottom hole assembly with or without the drill bit. Prior art bottom hole assemblies generally include one or more formation evaluation sensors, such as sensors for measuring the resistivity, porosity and density of the formation. Such bottom hole assemblies also include devices to determine the BHA inclination and azimuth, pressure sensors, temperature sensors, gamma ray devices, and devices that aid in orienting the drill bit a particular direction and to change the drilling direction. Acoustic and resistivity devices have been proposed for determining bed boundaries around and in some cases in front of the drill bit.
In practice, the bottom hole assemblies are manufactured for specific applications and each such version usually contains only a selected number of devices and sensors. Additionally, such BHA's have limited data processing capabilities and do not compute the parameters downhole that can be used to control the drilling operations. Instead, such bottom hole assemblies transmit data or partial answers uphole via a relatively small data-rate telemetry system. The drilling decisions are made at the surface based on the information provided by the BHA, data gathered during drilling of prior wellbores, and geophysical or seismic maps of the field. Drilling parameters, such as the weight-on-bit, drilling fluid flow rate, drill bit r.p.m. are usually measured and controlled at the surface. The prior art bottom hole assemblies do not provide a comprehensive or integrated approach to drilling wellbores as more fully explained below.
The operating or useful life of the drill bit, mud motor, bearing assembly, and other elements of the BHA depends upon the manner in which such devices are operated and the downhole conditions. This includes rock type, drilling conditions such as pressure, temperature, differential pressure across the mud motor, rotational speed, torque, vibration, drilling fluid flow rate, force on the drill bit or the weight-on-bit ("WOB"), type of the drilling fluid used and the condition of the radial and axial bearings.
Operators often tend to select the rotational speed of the drill bit and the WOB or the mechanical force on the drill bit that provides the greatest or near greatest rate of penetration ("ROP"), which over the long run may not be most cost effective method of drilling. Higher ROP can generally be obtained at higher WOB and higher rpm, which can reduce the operating life of the components of the BHA.
If any of the essential BHA component fails or becomes relatively ineffective, the drilling operation must be shut down to pull out the drill string from the borehole to replace or repair such a component. Typically, the mud motor operating life at the most effective power output is less than those of the drill bits. Thus, if the motor is operated at such a power point, the motor may fail prior to the drill bit This will require stopping the drilling operation to retrieve and repair or replace the motor. Such premature failures can significantly increase the drilling cost. It is, thus, highly desirable to monitor critical parameters relating to the various components of the BHA and determine therefrom the desired operating conditions that will provide the most effective drilling operations.
The drill bit speed can be selected by controlling the fluid flow through the mud motor or by controlling the rotary motor speed at the surface. The mud motor operating efficiency depends primarily upon the differential pressure across the mud motor. However, the mud motor, if operated at the optimum efficiency may provide higher rate of penetration, but the presence of unfavorable drilling conditions, such as high stator temperature, excessive vibration and WOB, etc. may significantly reduce the operating life of the mud motor. Similarly drilling at relatively high ROP through hard rocks may quickly wear out the drill bit. Relatively high ROP may also produce undesirable amounts of vibrations, whirl, stick-slip, axial and radial displacement of the BHA. Drilling at a lower drilling rate may result in significantly extending the life of the drill bit, mud motor, bearing assembly or other elements of the BHA, thereby reducing the number of retrieval trips to repair or replacement or repair of the BHA. A comprehensive strategy can result in drilling wellbores in less time and at less cost, because each BHA retrieval and repair trip can take several hours and can significantly increase the equipment cost. Prior art bottom hole assemblies fail to provide any comprehensive approach to the drilling.
Physical and chemical properties of the drilling fluid near the drill bit can be significantly different from those at the surface. Currently, such properties are usually measured at the surface, which are then used to estimate the properties downhole. Fluid properties, such as the viscosity, density, clarity, pH level, temperature and pressure profile can significantly affect the drilling efficiency. Downhole measured drilling fluid properties can provide useful information about the actual drilling conditions near the drill bit.
The present invention addresses the above noted problems and provides a an integrated BHA that utilizes interactive dynamic models to monitor physical parameters relating to various elements in the BHA (including drill bit wear, temperature, mud motor rpm, torque, differential pressure across the mud motor, stator temperature, bearing assembly temperature, radial and axial displacement, oil level in the case of sealed-bearing-type bearing assemblies, and WOB), determines the fluid properties downhole, determines the drilling parameters (force on the drill bit or WOB, fluid flow rate, and rpm) that will provide enhanced drilling rate and extended BHA life, i.e., greater drilling effectiveness and operates the various downhole controllable devices to achieve higher drilling effectiveness.